Unconventional reservoirs are reservoirs that do not meet the criteria for conventional production, that is, oil and gas reservoirs whose porosity, permeability, fluid trapping mechanism, or other characteristics differ from conventional reservoirs such as highly porous and permeable sandstone and carbonate reservoirs. Examples of unconventional reservoirs include coalbed methane, gas hydrates, shale gas, fractured reservoirs, and tight gas sands. Unconventional reservoirs such as tight gas sands reservoirs are defined as sandstone formations with less than about 0.1 millidarcy permeability and low porosity. Production from tight gas sands or shale reservoirs depends on the presence of natural fractures in the reservoir. Those fractured areas in the unconventional reservoir may act as sweet spot for production purposes. It has been estimated that the total-gas-in-place in the United States may exceed 15,000 trillion cubic feet where unconventional reservoir may contain majority of it.
In the exploration of oil and gas, it is often desirable to characterize the hydrocarbon content of prospective formations. While unconventional reservoirs may be continuous and therefore completely charged with gas, it is not to say that a well drilled anywhere in the reservoir will be as good a well as one drilled somewhere else. Accordingly, there are sweet spots associated with natural fractures where greater production may be realized. Finding the sweet spots is vital to drilling wells that will be economically producible.
In addition to finding the best production spots of unconventional reservoirs, determining optimal seismic data acquisition geometry for reservoir characterization is also useful and advantageous.
Unfortunately, conventional methods for characterizing fractures in unconventional reservoirs suffer from a variety of disadvantages. Conventional methods for characterizing fractured reservoirs include image logs, empirical methods, gravity and magnetic surveys as well as specialized wire line logs, core sampling, and seismic surveys.
While core sampling can provide the most detailed and high resolution information about a formation's petrophysical properties, unfortunately, taking core samples is a time-consuming, laborious, and costly process, fraught with numerous technical complications and pitfalls. Additionally, core samples often require intensive laboratory analysis and hence, high costs and delays. Often, taking a full core sample of a wellbore is simply not feasible, particularly for deep and highly deviated wells. Furthermore, core samples are extremely difficult to recover and accurately measure in a laboratory setting as the core samples must be kept at reservoir conditions to preserve their state for analysis.
Sampling while drilling is another common technique to ascertain petrophysical properties of a formation. This method can be classified as a cruder form of core analysis. Therefore, this conventional method suffers from significant limitations, particularly with respect to the amount of samples that may be taken while drilling. Furthermore, analysis of these samples is time-consuming and laborious as well.
Another common form of evaluating petrophysical properties of formations is logging. Logging tools provide a variety of noninvasive evaluation techniques for evaluating formations and detecting hydrate presence. Unfortunately, conventional logging tools only provide limited information about a formation's petrophysical properties. Individual logging techniques often fail to accurately detect and accurately evaluate the nature and composition of subterranean formations and the hydrocarbon contained therein.
Other conventional approaches for characterizing fractured formations such as image logs also suffer from a variety of disadvantages. Image logs, when available, are usually only run for a limited portion of the wellbore length. In particular, image logs are limited to the direct well bore region and only yield fracture count information. In this way, image logs fail to yield desired information to sufficiently characterize the formation. Further, image logs are difficult to correlate with seismic surveys due to different resolution limits. Also, image logs are not a cost effective solution at present day gas prices.
Cross dipole sonic logs are yet another way of characterizing fractured formations. Dipole sonic logs return S-wave velocity anisotropy due to the presence of vertical fractures. The observed S-wave anisotropy must then be converted to P-wave anisotropy for fracture reservoir characterizations. Unfortunately, S-wave to P-wave anisotropy parameter conversion is generally done using empirical relationships which are not always accurate and may return erroneous values.
All the above methods evaluate the reservoir at sparse locations, hence lack spatial resolution; whereas seismic surveys can help to evaluate the entire reservoir from the subsurface. A significant problem with seismic methods rests in its low depth resolution. Therefore, well-ties are required to get better depth resolutions for reservoir characterization from seismic data. For fractured reservoirs, cross-dipole sonic logs give S-wave anisotropy, but conventionally acquired seismic data consist of P-waves. Therefore, to perform well-ties for fracture characterization, empirically obtained P-wave anisotropy data is the only source. Since P-wave anisotropy parameters are empirically obtained, well-ties often return erroneous estimates for further fracture characterization. This problem can be solved by acquiring S-wave data, which is not common due to its high cost and difficult acquisition process.
Accordingly, there is a need for enhanced fracture characterization methods of unconventional reservoirs that address one or more of the disadvantages of the prior art.